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FERC Proposes to Lift Capacity Price Cap

In an effort to facilitate the development of a market for capacity reassignments, the FERC has issued a notice of proposed rulemaking (NOPR) (pdf) to lift the price cap on all transmission customers reassigning capacity beyond October 1, 2010.

In Order No. 888, the FERC determined that a transmission owner’s Open Access Transmission Tariff (OATT) must permit the reassignment of firm transmission capacity.  But because the Commission could not discern a competitive market for capacity reassignments at the time Order No. 888 was enacted, it established a rate cap for those transactions.  Rule changes designed to enhance competition in this secondary market were developed through subsequent Order Nos. 890 and 890-A, in which the FERC expressed the goal of removing price caps and commenced a two-year Commission staff study period.

That study is now complete and the report (pdf) was published on April 15, 2010.   Using data filed by transmission providers, the FERC staff observed almost 35,000 capacity reassignments by 26 transmission providers during the period from May 2007 through the end of 2009. The number of reported transactions and volume of capacity reassigned rose dramatically over the two and a half year period.  The FERC staff thus concluded that the removal of the price cap did not raise anticompetitive concerns and that resellers used the secondary market mainly to derive value from unneeded capacity.

Increased competition in the capacity reassignment market will be welcome news to project developers – including renewable project developers – as it increases access to transmission capacity that traditionally would have been fully subscribed by existing generators.  Comments on the proposed rule must be filed within 60 days of the publication in the Federal Register (early July) and may be filed by mail, by hand or at the FERC website.

Federal Law May Impede Development of State Feed-In Tariffs

Feed-in tariffs are a relatively frequent topic here at Renew NewEngland.  Mostly we've been curious about the strange absence of this proven method of spurring renewable energy development, as New England states tried seemingly everything to build a green economy.  It's a sign of just how fast the field is changing that in the year that we've been writing this blog, feed-in tariffs have moved from speculation to reality in North America, with new FITs in Hawaii, Oregon, Vermont, California, and Ontario, along with smaller efforts like Gainesville, Florida.  Purists--or at least energy lawyers of a certain vintage--will note that FITs in the US are actually old news, citing PURPA, which partially explains why US policymakers are reluctant to try anything that sounds like fixed price, long term contracts for renewable energy. 

An NREL report issued earlier this year explores the impending collision between these new FITs and this legacy legal framework. The report, entitled Renewable Energy Prices in State-Level Feed-in Tariffs: Federal Law Constraints and Possible Solutions (pdf), discusses the limits imposed by PURPA and the Federal Power Act on states' ability to craft feed-in tariffs, and lists possible steps FERC or Congress might take to remove (or at least clarify) those constraints.  Perhaps more importantly, the report provides guidance to state regulators and legislators in crafting feed-in tariffs in the existing legal landscape.

The report's detailed analysis of PURPA and the FPA doesn't easily lend itself to summary in a blog post, but the overall conclusions are relatively straightforward: under current law, a state cannot simply require a utility to purchase electricity from a seller at specified prices for a specified duration (the essence of a FIT) without conforming its actions to the mandates of PURPA.  At the very least, this complicates--and may ultimately frustrate--any effort to enforce a FIT.  Moreover, "given the FPA's requirements, a state-level feed-in tariff, as defined above, outside of PURPA, is not legally possible in the United States today."

It's unclear to what extent states are aware of these constraints as they craft their FIT legislation.  PURPA doesn't apply in Hawaii (no interstate commerce) so that state was free to craft a PURPA-free FIT; the convoluted structure of Vermont's SPEED program may reflect these concerns.  In California, Southern California Edison challenged the PUC's jurisdiction to set rates, a decision is expected soon. Unlike renewable portfolio standards, where state efforts to go it alone undermine the potential of larger markets for renewable energy credits, state (or municipal) level FITs allow for much needed experimentation, to craft FITs that account for differences in market structure, renewable resources and policy goals.  For example, California's unique new solar FIT will include an auction mechanism and vary in price based on the time of day during which the electricity is generated.  While successes are great, even failures can be instructive.  To the extent that these requirements needlessly hinder such experimentation, they are a barrier to renewable energy development in the US.

FERC Seeks Comment on Barriers to Integration of Renewables

Last Thursday, FERC issued a Notice of Inquiry (pdf) seeking comments on the extent to which barriers exist that may inhibit the integration of certain renewable energy sources into the electric grid.   FERC particularly identified locational challenges and limited dispatchability as problems associated with resources like wind and solar that can adversely affect reliability and (in the realm of “unintended consequences”) can require the addition of more conventional resources for balancing purposes.

In this proceeding, FERC intends to explore how existing rules, regulations, tariffs, or even industry practices hinder the development of variable energy resources, through either discrimination or imposing unjust rates, and as part of this, to consider potential reforms.   In the past, FERC has adopted targeted rules to encourage renewable resource development – such as standardizing interconnection agreements for wind resources (Order 661), or adopting a reduced penalty for imbalances caused by intermittent resources (Order 890).  In this proceeding, FERC will take a “fresh look” at all existing policies and rules, “with the aim of removing unnecessary barriers to transmission service and wholesale markets for Variable Energy Resources  (“VERs”) and other technologies that may aid their integration, and promoting greater efficiencies that ultimately will reduce costs to consumers.“  The seven specific areas FERC singled out are:

1. data and reporting requirements, including the use of accurate forecasting tools;
2. scheduling practices, flexibility, and incentives for accurate scheduling of VERs;
3. forward market structure and reliability commitment processes;
4. balancing authority area coordination and/or consolidation;
5. suitability of reserve products and reforms necessary to encourage the efficient use of reserve products;
6. capacity market reforms; and
7. redispatch and curtailment practices necessary to accommodate VERs in real time.

However, FERC will not consider transmission planning and cost allocation issues, as these are being considered in another docket. (Transmission Planning Processes Under Order No. 890, Docket No. AD09-8-000) Comments are due 60 days from publication in the Federal Register, expected to be the last week in March, 2009.

A Manufacturing Tax Credit Announcement & A Production Tax Credit Order

Last week, the Obama administration announced $2.3 billion in manufacturing tax credits, specifically designed to stimulate investment (and job growth) in the manufacturing sector associated with clean energy projects.  (For more on the manufacturing tax credit, see our previous post.)  With persistent unemployment plaguing the manufacturing sector, it makes sense that this initiative is receiving a lot of attention from the administration – and in the press.

Receiving less publicity – but reducing regulatory uncertainties for banks investing in certain renewable energy projects – is a recent FERC ruling regarding the production tax credit.  As noted in the Order (pdf), renewable energy project developers rely on passive equity investors that can monetize a project’s production tax credits.  By removing any concern that tax equity investors could be viewed as “affiliates” of a public utility that would have to be disclosed in a change in status filing under Section 203 of the Federal Power Act or would require a FERC waiver prior to investing, FERC’s order helps ensure that prospective tax equity investors will not be discouraged from investing in new wind power projects due to concerns over increased regulatory burdens.

For more information on FERC’s oversight of renewable projects, contact Randy Rich in Pierce Atwood’s Washington, DC office. 

FERC Proposes Updates to Form 556

The FERC has recently proposed (pdf) to revise § 131.80 of its regulations, which governs the certification of “qualified facilities” (QFs).  (Under the Federal Power Act, QFs may be “eligible” facilities (solar, wind, waste or geothermal facilities of any size, within certain dates of construction) or “non-eligible” facilities (qualifying small power production facilities of no more than 80 MW).  For more on the benefits of QF status, click here.)  The current regulation contains FERC Form 556 that is used in the certification of qualifying status for existing or proposed small power production or cogeneration facilities, along with general instructions for completing the form.

Many of the proposed changes are ministerial in nature, designed to reduce the filing burden on both generators and the FERC.  For example, the text of Form 556, now included in the text of the Rule itself, will be removed from the rule (which will allow minor changes to the form to be made without requiring a formal rulemaking process).  In addition, under the proposed revisions, all filing will now be accomplished electronically (for the convenience of both the filers and FERC, and to enable filing data to be compiled and made public more easily).  The proposed rulemaking would also make explicit the FERC’s authority to grant waiver of the filing requirement upon petition where good cause is shown; make various other corrections and clarifications to the text of the regulations, and eliminate the requirement that QFs file notice of self-certification in the Federal Register in addition to filing with the FERC.

But many small QF facilities may be most interested to learn that the proposed revisions also include an exemption from the filing requirement for the smallest applicants, those with a net power production capacity less than or equal to 1 MW.  The rationale is that generators with capacity of 1 MW or less are likely residential power generators (or small businesses), and may lack the resources – electronic and legal – to file Form 556.   Before the rule becomes final, the FERC is seeking comments on this proposed exemption:  whether the 1 MW cutoff is the appropriate size, and whether the generation data from these smallest QFs should be generated in some alternate fashion.  Comments are due December 21, 2009.

 

Regulatory Oversight: Who Will Regulate Cap and Trade?

As climate legislation slowly wends its way through the Senate and the economy struggles to recover from the impact of toxic assets, concerns over climate trading fraud abound.  Skeptics are wondering whether a cap and trade regime will inevitably render the market vulnerable – again – to under-regulated trades of little-understood assets.

Somewhat less discussed is who will regulate the trades in a federal cap and trade program.  The EPA has the authority to regulate emissions and has recently announced mandatory reporting rules (pdf) for greenhouse gasses.

There is some debate about whether EPA has the authority to implement a cap and trade program, however.  Most acknowledge the EPA could regulate carbon under the existing Clean Air Act rules; others believe (pdf) that the EPA has sufficient existing authority to implement its own cap and trade system.  But both Industry and the Obama administration have reservations about leaving the regulation of carbon emissions to the EPA.  And legislation proposed by Republicans, longstanding opponents of EPA regulation of carbon, would limit the EPA’s authority to implement cap and trade.

Assuming the EPA can’t or won’t take the regulatory lead, FERC seems like a likely contender.  Under EPAct 2005 (pdf), FERC has authority to prosecute manipulation of energy prices. 

But this summer, the Commodity Futures Trading Commission announced its intent to evaluate whether the Chicago Climate Exchange (CCX), an unregulated market, should be regulated because it “performs a significant price discovery function.”  (This authority over Significant Price Discover Contracts (SPDC (pdf)) is new; it was exercised by the CFTC for the first time in July, 2009, making CCX only the second target.) 

And so, a jurisdictional dispute (pdf) between FERC and CFTC is brewing, but not for the first time:  a similar dispute between the agencies prior to re-authorization of the CFTC is described here (pdf).  A detailed description of the regulatory gaps between these two agencies can be found here (pdf):  one key gap is that while FERC regulates contracts for “physical energy,” that energy is often traded through standardized forward contracts, which could also be considered futures and subject to CFTC jurisdiction.  Will energy-related emissions be traded as futures under the CFTC or as energy under FERC?  Bridging that gap will be critical when it comes to implementing any federal cap and trade legislation that may emerge. 

FERC and Maine Sign MOU on Ocean Tidal Power

Recognizing Maine’s “vast, untapped renewable ocean energy resources, including tidal power resources” and the state’s potential to become “an international proving ground for testing promising new technologies in state waters”, FERC Chairman Jon Wellinghoff today signed a Memorandum of Understanding (MOU (pdf)) with the State of Maine, providing that the federal and state regulators will coordinate – and streamline – the permitting process for tidal energy projects.

The MOU is the first of its kind on the East Coast (Washington signed a similar MOU (pdf) in June, 2009; Oregon signed one (pdf) in March, 2008); and was recommended (pdf) by the tidal power subcommittee of Maine’s Ocean Energy Task Force (OETF) earlier this year, which noted that a lack of coordination between the state and FERC permitting processes can limit the ability to move projects forward.

The MOU agreement will reinforce the close working relationship between federal and state regulators needed to ensure timely consideration of pilot project license and commercial project license applications.  Under the agreement, for instance, FERC and Maine agree that:

• Each will notify the other when they become aware of a potential applicant seeking a preliminary permit, project pilot license, or other license to develop a hydrokinetic tidal energy project;
• Maine will take action on a demonstration hydrokinetic tidal energy project’s application for a state permit and water quality certification within 60 days of the state’s acceptance of the application; and
• Both will designate management contacts to work through any procedural issues that arise in the review of a particular proposed tidal energy project.

In addition to these provisions designed to streamline the permit review process, the MOU also seeks to coordinate the substantive review of pilot projects and support the development of tidal energy by sharing critical data gathered from these innovative projects.  Maine commits to support FERC’s establishment of a permit process to allow short-term hydrokinetic tidal energy projects and FERC agrees to review permits with a view to ensure projects are compatible with Maine comprehensive plans and offshore wind energy test areas, as defined by new Maine law (pdf), which creates a streamlined DEP permit process for tidal energy demonstration projects.  Recognizing that gathering information regarding the economic and technical feasibility of new ocean technologies can be a stumbling block for their development, Maine and FERC also agree that any required pre- and post-licensing studies for pilot projects should be reasonable in scope and that any data gathered on pilot projects should be shared.

The MOU will promote the close working relationship between federal and state regulators needed to ensure timely consideration of pilot project license and commercial project license applications.  This is good news for the tidal power development community, and addresses concerns like those raised by the OETF, that an uncoordinated approach to permitting can lead to the failure of projects - like Finavera Renewables' (pdf) proposed tidal project in Makah Bay, WA - to make it past the planning stage.  The new framework will provide an efficient and predictable permitting process that will better enable the United States – and specifically the State of Maine – to compete effectively in the global race to develop tidal power technology and power projects.

Like Water to DC

In a recent decision (pdf), the FERC granted preliminary approval to a single transmission line, proposed by Hydro-Quebec, NStar and NE Utilities.  The line will be a high-voltage direct current (DC) line, bringing 1,200 MW of hydropower from Canada to the ISO-New England region via a southern New Hampshire tie-in.  The project is proposed as a participant-funded project, meaning the proposal does not seek to socialize the costs among the ISO-New England states.  Instead, the project will essentially be funded by a long-term contract for the energy it’s designed to transmit. 

Canadian officials cheered this decision by the FERC; in their view, this is the first FERC approval of a major long-term contract for Canadian hydropower since the 1980s and marks the first time hydro power has been acknowledged by a federal agency as a clean source of power.  Canadian hydropower developers – on both coasts – are cheering these developments, too, concluding that Canadian hydropower will now be a welcome player under the Obama Administration’s energy policy. 

But south of the border, several developers of smaller renewable projects in northern New Hampshire claim the Hydro-Quebec transmission project will have a chilling effect.  These wind and biomass projects face a host of technical, regulatory and financial hurdles, but they also require transmission upgrades in order to be viable, and interconnection with the Hydro-Quebec line is not an option.  The Hydro-Quebec line would be a high-powered direct current line, requiring expensive transformers to change it into alternating current that goes to people’s homes.  Developers in New Hampshire worry that the massive Hydro-Quebec line would make improvements to the existing transmission system seem unnecessary to NH officials and ISO-New England, and they can’t afford the upgrades without socializing the costs or receiving financial support from the state. 

Eliciting a Response

Current ISO-NE demand response (DR) programs are set to expire in one year (June 1, 2010) and ISO-NE has initiated a stakeholder process (pdf) to decide what comes next.  Key features of two of the DR programs currently offered by ISO-NE include: 

• Real-Time Price Response Program, under which participants may interrupt their power use when the forecast price of power reaches $100/MWh or more and the ISO lets participants know the eligibility period is open.  Participants are paid $100/MWh or the LMP at the time of their interruption, whichever is higher. 
• Day-Ahead Load Response Program, which allows participants to submit offers to interrupt power use along with submissions of supply offers in the day-ahead energy market.  Participants are paid the Day-Ahead LMP for the cleared interruptions, and real-time deviations are charged or credited at the Real-Time LMP.

In a recent FERC filing (pdf), ISO-NE noted that this stakeholder process touches on a variety of policy issues.  Many of these policy issues reflect the need to encourage demand response (making it economically advantageous to reduce power use at times of peak load and providing DR opportunities to all customer classes, for example) without distorting the market (by offering DR subsidies disproportionate to their actual benefits to transmission system reliability). 

Market-based capacity programs like those currently available at ISO-NE can inspire huge growth in DR, particularly in the wholesale and industrial customer classes.  According to ISO-NE, DR resources (mostly wholesale and industrial) in the region have gone from 100 MW to 2,500 MW since the inception of these programs.  Still, the FERC estimates (pdf at 33) there could be 41 GW of demand response available in the United States; if that estimate’s right, there should be a lot more to be found in New England, especially among customers who lack direct access to capacity programs, like residential customers.  The rapidly emerging SmartGrid standards will have a large impact on how DR programs are designed – and how much access various customer classes have to them.  Makes sense, then, that the most recent meeting of the ISO-NE Demand Resources Working Group was held jointly with the Demand Resources IT Infrastructure Working Group. 

ISO-NE intends (pdf) to file an updated report on this stakeholder process with the FERC by the end of July, 2009, detailing areas of consensus.  Any rule changes resulting from this discussion will be presented to stakeholders and filed with the FERC by the end of 2009.

Smart Grid Update

The first half of 2009 has been a wild ride for the smart grid, as this wonky electric industry dream has gone mainstream, complete with a presidential shout-out in a major economic speech and a super bowl commercial. Last week brought a slew of smart grid news.

On May 18, networking giant Cisco announced plans to enter the smart grid infrastructure market, which it expects to grow to over $20 billion a year within the next five years.

That same day, the Department of Energy announced that it would modify its plans to distribute the $4.5 billion in smart grid stimulus funds, by raising the cap on individual investment grants from $20 million to $200 million, and for demonstration projects from $40 million to $100 million.  Industry players had argued that the previous caps weren't large enough to support large scale end-to-end deployments. The final guidelines are expected to be released June 17.

In the same announcement, NIST released 16 smart grid interoperability standards, the product of the first Smart Grid Interoperability Conference held April 28th and 29th.  These standards, mostly governing cybersecurity and home area networks, were the low-hanging fruit of what promises to be a contentious standards-development process.  That work continued at the second workshop last week--PG&E's Next100 blog has a good description of what these workshops involve, and Katie Fehrenbacher at Earth2Tech has a rundown on the accelerated timeline for smart grid standards development.  Title 13 of the 2007 Energy Independence and Security Act, which laid out the legislative framework for this process, calls for FERC to adopt these standards in a rulemaking once the NIST process has developed "sufficient consensus."  If you want an inside glimpse of the process, check out the standards conference's wiki.

The day after the DOE/NIST announcement, FERC requested supplemental comments (pdf) on its Smart Grid Policy Statement--initial comments were due May 2nd--to address steps the Commission might take in assisting utilities applying for DOE Smart Grid funds.  Noting that the DOE's draft Funding Opportunity Announcement calls for applicants to identify and confirm funding sources for proposed projects, the Commission seeks input "how it should address requests for rate recovery that may be necessary for public utilities to qualify for awards," and whether a conditional approval may be useful. Comments on that Notice are due June 2nd.